Rock permeability and formation fluid viscosity are key petrographical parameters throughout all stages of the oil or gas field development. These parameters are crucial for reservoir evaluation, optimal completion, production optimization and drainage pattern optimization for maximum hydrocarbon recovery. At the same time permeability and viscosity measurements are one of the most difficult measurements to get in a well.
Despite the fact that viscosity is a property of the formation fluid while permeability is formation property, measurements of these parameters and the methods used are closely related with each other. Permeability measurements normally include the measurement of two physical properties—mobility (ratio of permeability to formation fluid viscosity) and fluid viscosity.
Existing direct methods for pore fluid viscosity and formation permeability determination include pore fluid sampling with subsequent analysis, petrophysical and geo-chemical analysis of core plugs, pressure buildup and drawdown tests. All these methods require long-time measurements and high expenses for the implementation thereof. Besides, they provide not continuous information, i.e., contain only data of certain number of points along the borehole.
Acoustic measurements enable measuring a fluid mobility. To determine the pore space permeability additional information of the fluid viscosity is required. Viscosity measurement is a complex problem and normally requires auxiliary measurements.
From the prior art methods for rock properties' determination during the formation thermal treatment are known. Thus, in the USSR Certificate of Invention No. 1125519 a method for determining properties of productive formations is described; in accordance with this method a reservoir undergoes a thermal treatment and nuclear-magnetic or acoustic logging is performed before and after the thermal treatment. Free-fluid index, longitudinal relaxation time and porosity are measured, and oil recovery ratio is evaluated based on the measurement data. The formation thermal regime is in this case set by means of thermal agent injection or by establishing in-situ combustion.
In another patent—U.S. Pat. No. 6,755,246 a method is described in accordance with which a formation is passively or actively heated to increase the formation fluid temperature thus changing a relaxation time T2 of spin echo measurements which is used to identify and quantify heavy oil saturation. This method disadvantage is that it relies on empirical ratios during the measurement results' interpretation, which in a number of cases dramatically reduces the accuracy and applicability thereof. A disadvantage of NMR method is that the decay time constant in some formations, e.g., in low-permeability sandstones, is very small which prevents measuring signals with sufficient accuracy. The main problem relating relaxation times to formation permeability is that the pores studied by NMR need not to be hydraulically connected. Therefore an impermeable medium containing disconnected vugs could yield the same T1 decay curves as a permeable rock containing connected pores.